Process For Recovering Hydrogen And Carbon Dioxide

ABSTRACT

The present invention provides a process for recovering hydrogen and carbon dioxide from a process stream utilizing a carbon dioxide separation unit and two membrane separation units. The present invention further provides a process within a hydrogen generation plant to increase recovery of hydrogen and capture equal to or greater than 80% of the carbon dioxide in the syngas stream. By using the process of the present invention, especially in terms of a hydrogen generation plant, it is possible to increase recovery of hydrogen and capture of the carbon dioxide in the syngas stream by balancing the recycle of the hydrogen rich permeate from the hydrogen membrane separation unit to the process unit and/or the water gas shift as capacity allows when a carbon dioxide separation unit, a carbon dioxide membrane separation unit and a hydrogen membrane separation unit are utilized.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Patent ApplicationNo. 61/487,490, filed May 18, 2011, the entire content of eachincorporated herein by reference.

FIELD OF THE INVENTION

The present invention relates to a process for recovering hydrogen andcarbon dioxide from a process stream utilizing a carbon dioxideseparation unit and two membrane separation units. The present inventionfurther provides for a process within a hydrogen generation plant toincrease recovery of hydrogen and capture equal to or greater than 80%of the carbon dioxide in the syngas stream utilizing a carbon dioxideseparation unit and two membrane separation units.

BACKGROUND

Hydrogen is an important feedstock for many chemical and petrochemicalprocesses. However, hydrogen production is associated with large amountsof carbon dioxide (CO₂) emissions. Accordingly, it is desirable to notonly provide a means to produce hydrogen but also a means to recover thecarbon dioxide associated with the hydrogen production. With increasedemission regulations and a possible future CO₂ tax there is a need todevelop carbon dioxide capture solutions. The cost of capture can impactthe cost of hydrogen production. Therefore, it is important to develop asolution with lower cost of capture and improved efficiency of hydrogenproduction plant.

Physical or chemical solvents such as rectisol, selexol, amines,potassium carbonate etc. have been used traditionally for many decadesto absorb carbon dioxide from syngas in hydrogen plants, HYCO (hydrogenand carbon monoxide co-production) plants. However, the process ofsolvent absorption requires absorber and stripper columns with very highcapital costs. The scrubbing solvent needs to be regenerated bytemperature swing or pressure swing in order to release the absorbedcarbon dioxide. The regeneration process can involve large amounts ofsteam or compression energy resulting in high operating costs. Anotherdisadvantage of using the solvent absorber is that the purity of therecovered carbon dioxide may not be very high and further processingusing liquefaction and partial condensation may be needed. Example U.S.Pat. No. 6,500,241 describes the use of acid gas removal unit and autorefrigeration unit for removing carbon dioxide from syngas and PSAoff-gas. U.S. Pat. No. 4,553,981 and U.S. Pat. No. 7,682,597 describethe use of a carbon dioxide scrubber downstream of the shift reactor toremove carbon dioxide from syngas.

Carbon dioxide can be captured from a hydrogen plant by using cryogenicprocessing viz, partial liquefaction or distillation at lowtemperatures. Such a process is favorable at higher carbon dioxideconcentrations. In hydrogen plants, carbon dioxide can be captured fromseveral different locations in the process train including processsyngas or flue gas. Flue gas processing can pose several challengesbecause of many new impurities that therefore make the capture processvery expensive. Carbon dioxide from process gas can be captured fromhigh pressure syngas before pressure swing adsorption unit or frompressure swing adsorption off-gas. The concentration of carbon dioxidein the gas before pressure swing adsorption is much lower than in thepressure swing adsorption off-gas and hence the pressure swingadsorption off-gas is more suitable for cryogenic separation. U.S. Pat.No. 6,301,927 provides an example of an auto refrigeration process thatemploys the use of a compression and expansion turbine to liquefy carbondioxide and further separate it from other gases. Another patent, FRPatent No. 2877939 provides a way to remove carbon dioxide from pressureswing adsorption off-gas by using successive steps of compression andcooling to remove carbon dioxide by partial liquefaction and/ordistillation. This patent describes the use of a membrane on thenon-condensable gas to permeate hydrogen and recycle hydrogen back tothe pressure swing adsorption unit in order to increase hydrogenrecovery. However, carbon dioxide recovery for the unit is not veryhigh. In U.S. Pat. No. 4,639,257, provides the use of carbon dioxideselective membrane in combination with distillation column for a carbondioxide containing gas mixture in order to increase the recovery ofcarbon dioxide. A carbon dioxide selective membrane is used on theoverhead of the distillation column with carbon dioxide rich permeaterecycled back to feed or to the distillation column itself. Anothercarbon dioxide selective membrane is proposed for the feed gas beforethe distillation column in case the concentration of carbon dioxide isbelow equilibrium concentration at the freezing temperature of themixture. However, this patent is suitable for a gas mixture containingcarbon dioxide, nitrogen, methane and hydrocarbon. U.S. PatentPublication No. 2010/0129284, describes the use of a hydrogen selectivemembrane, a carbon dioxide selective membrane in combination with carbondioxide liquefier in order to increase the recovery of hydrogen andcarbon dioxide. However, carbon dioxide selective membrane is alwayslocated upstream of the liquefier requiring additional compression ofthe carbon dioxide permeate from the membrane feeding to the liquefier.

Hydrogen plants can emit large quantities of carbon dioxide into theatmosphere. Carbon dioxide capture solutions have been proposed in thepast using several different separation techniques like absorption,cryogenic, adsorption or membrane. There is always some hydrogen lossfrom pressure swing adsorption processes. In addition, there is somecarbon dioxide loss from the capture process which can be recovered byimproving the carbon dioxide capture process. If additional hydrogen andcarbon dioxide can be recovered from the capture process there can besignificant savings with regards to the size of reformer, natural gasconsumption, carbon dioxide tax etc. for the same size hydrogen plant.

Accordingly, there still exists a need for a process to recover bothhydrogen and carbon dioxide with a carbon dioxide recovery rate of atleast 50% from syngas, as well as a process for producing hydrogen in ahydrogen generation plant that allows for the overall capture of atleast 80% of the carbon dioxide, in the hydrogen production process.

SUMMARY

This present invention provides a method to more efficiently recoverhydrogen and carbon dioxide, preferably at least 50%, even morepreferably at least 75% and most preferably at least 90% of the carbondioxide. The present invention further provides the design for captureof at least 80%, carbon dioxide from syngas that allows for thesimultaneous production of medium to high amounts of hydrogen in thesyngas as a part of the production of hydrogen in a hydrogen generationplant. By using the process of the present invention, especially interms of a hydrogen generation plant, it is possible to increaserecovery of hydrogen and capture of the carbon dioxide in the syngasstream by balancing the recycle of the hydrogen rich permeate from thehydrogen membrane separation unit to the process unit and/or the watergas shift as capacity allows when a carbon dioxide separation unit, acarbon dioxide membrane separation unit and a hydrogen membraneseparation unit are utilized. The proposed use combines hydrogenselective membranes and carbon dioxide selective membranes together withcarbon dioxide separation units such that hydrogen and carbon dioxideare produced with increased recoveries and improved process efficiency,especially with regard to a hydrogen generation plant. Increasedhydrogen recovery by using hydrogen selective membranes can reduce thesize of the feed gas producing unit, natural gas consumption for feedand fuel etc for the same size hydrogen plant. Increased carbon dioxiderecovery will reduce the emissions of carbon dioxide into the atmosphereand will result in cost savings in case of a carbon tax.

DETAILED DESCRIPTION OF THE DRAWINGS

FIG. 1 provides a schematic of one embodiment of the present process.

FIG. 2 provides an expanded view of one variation of the carbon dioxideseparation unit of FIG. 1.

FIG. 3 provides an expanded view of another variation of the carbondioxide separation unit of FIG. 1.

FIG. 4 provides an expanded view of still a further variation of thecarbon dioxide separation unit of FIG. 1.

FIG. 5 provides a schematic of a second embodiment of the presentprocess.

FIG. 6 provides an alternative to the schematic of FIG. 5.

FIG. 7 provides an alternative to the schematic of FIG. 1.

DETAILED DESCRIPTION OF THE INVENTION

It is possible to efficiently recover hydrogen and carbon dioxide fromprocess streams obtained from process units which have a purificationstep that provides a hydrogen rich fraction which can be utilizeddownstream (more specifically, in the production of electricity) as inthe present process. While overcoming many of the disadvantages of theprior art systems that deal with the recovery of hydrogen and carbondioxide from such streams, this can be accomplished by integrating acarbon dioxide separation unit, a hydrogen selective membrane separationunit and a carbon dioxide selective membrane separation unit into theprocess for treating streams taken from such process units in the mannernoted herein. In addition, increased production of hydrogen and carbondioxide capture of equal to or greater than 80% from syngas in hydrogengeneration plants may also be accomplished by integrating a carbondioxide separation unit, a hydrogen selective membrane separation unitand a carbon dioxide selective membrane separation unit into theschematic of a hydrogen generation plant. Accordingly, two mainprocesses are proposed herein.

With regard to the first noted process, the proposed schematic includesa process unit, an optional compressor, a heat exchanger, a carbondioxide separation unit, a hydrogen selective membrane separation unitand a carbon dioxide selective membrane separation unit. With regard tothe second noted process, the proposed schematic includes a feed gasproducing unit, a pressure swing adsorption unit, an optionalcompressor, a heat exchanger, a carbon dioxide separation unit, ahydrogen selective membrane separation unit and a carbon dioxideselective membrane separation unit.

The processes of the present invention will be further described withregard to the figures contained herein. These figures are includedmerely for illustration purposes and are not intended in any way tolimit the processes of the present invention. The first process of thepresent invention as depicted in FIG. 1 involves the recovery ofhydrogen and carbon dioxide from a process stream (1) that is obtainedfrom a process unit (0). As used herein, the phrase “process unit”refers to any unit which includes a purification step that results inthe production of a hydrogen rich fraction that can be used downstream.More specifically, the “process unit” is a unit in which as one step ofthe process, hydrogen is removed from a feed stream in such a mannerthat allows for the recovery of hydrogen in a more concentrated formthan presented in the original noted feed stream—a hydrogen richfraction that is the product stream (23)—and a tail gas stream that isthe process stream (1).

The feed gas (15) that is supplied to the process unit (0) can be anyfeed stream that will typically be subjected to treatment for theremoval of hydrogen. For example, the feed gas (15) may be a feed gas(15) produced in a feed gas producing unit (31), for example a feed gas(15) from a reformer unit/water gas shift unit, a partial oxidation unit(POx), an autothermal reformer unit (ATR), syngas from a coalgasification unit, refinery off gas or any other gas mixture thatcontains hydrogen, carbon monoxide and carbon dioxide as components inthe gas mixture. In the more typical situation, the feed gas (15) willbe the product of a hydrocarbon containing feed stream (16) that hasbeen subjected to at least steam hydrocarbon reforming (preferably steammethane reforming) (not shown in FIG. 1). In a further embodiment, thefeed gas (15) will be the product of a hydrocarbon feed stream (16) thathas been subjected to a reformer unit/water gas shift unit, an ATR unit,a Pox unit or a gasification unit. In the more preferred situation, thefeed gas (15) will be the product of a hydrocarbon containing feedstream (16) that has been subjected to at least steam hydrocarbonreforming and water gas shift (not shown in FIG. 1). In a still furtherembodiment, the feed gas (15) will be the product of a gas stream thathas been subjected to pre-reforming and steam hydrocarbon reforming andfinally, the product of a gas stream that has been subjected topre-reforming, steam hydrocarbon reforming and water gas shift (notshown in FIG. 1). Each of these is described more specifically belowwith regard to the second process. In addition, those of ordinary skillin the art will recognize that the present invention is not meant to belimited by the hydrocarbon feed stream (16) which will ultimately formthe feed gas (15) utilized in the present invention. Depending upon thesource of the hydrocarbon feed streams (16), those of ordinary skill inthe art will recognize that there will likely be small amounts of othercomponents present in the ultimate feed gas (15), e.g. inerts such asnitrogen. Accordingly, while reference is made herein in more generalterms to the major components (such as hydrogen, carbon monoxide, carbondioxide, methane and water vapor) of the hydrocarbon feed streams (16)and feed gas (15), those skilled in the art will recognize that inertssuch as nitrogen are also present and make up part of the stream.

Preferably, the process unit (0) utilized will be a pressure swingadsorption unit that is used to recovery and purify hydrogen, althoughthose of ordinary skill in the art will recognize that any other unitthat functions to carry out hydrogen purification may is alsocontemplated to be within the scope of the present invention. Thepressure swing adsorption unit utilized can be any pressure swingadsorption unit known in the art and can comprise anywhere from two totwelve adsorption beds (not shown) although more adsorption beds may beutilized. During the process of hydrogen purification, each of theadsorption beds (not shown) will individually under go a cycle thatcomprises: a) pressurization with pure hydrogen product, b) constantfeed and hydrogen product release; c) pressure equalization to transferhigh pressure hydrogen-rich void gas to another bed at low pressure, theother bed being about to commence product pressurization; d)depressurization to slightly above atmospheric pressure; e) purge usingproduct hydrogen; and f) pressure equalization with another bed athigher pressure to accept hydrogen-rich void gas. Preferably theadsorbents used in the pressure swing adsorption unit (0) include, butare not limited to, activated alumina, activated carbon, zeolite andtheir combinations. As a result of hydrogen purification, two separategas streams are obtained—one that is a gaseous medium to very highpurity hydrogen stream that is withdrawn and used as a hydrogen product(23) and the other which is often referred to as a pressure swingadsorption tail gas (referred to hereinafter as the “process stream”)which is withdrawn after desorption of the adsorption bed as processstream (1). The process stream (1) is withdrawn from the adsorption bedsof the pressure swing adsorption unit during the depressurization andpurge steps. As used herein, the phrase “medium to very high purityhydrogen stream” refers to greater than 99% hydrogen. Furthermore, asused herein, the phrase “high purity hydrogen stream” refers to greaterthan 99.9% Hydrogen.

The removal of hydrogen product (23) from the feed gas (15) in theprocess unit (0) results in a process stream (1) that is purged from theprocess unit (0). This process stream (1) contains at least carbondioxide, hydrogen and methane. Typically, the process stream contains atleast methane, carbon monoxide, carbon dioxide, water, and anyunrecovered hydrogen.

In the process of the present invention as depicted in FIG. 1, theprocess stream (1) obtained from the process unit (0) is further treatedto remove additional hydrogen and carbon dioxide by passing the processstream (0) through a carbon dioxide separation unit (4), a hydrogenselective membrane unit (7) and a carbon dioxide selective membrane unit(10).

Prior to being introduced into the carbon dioxide separation unit (4),the process stream (1) obtained is optionally compressed in a firstcompressor (2). As used throughout, the term “compressor” is meant toinclude not only a compressor that has a single stage for compressionbut also a compressor that includes multiple stages for compression(typically from two to eight stages) with means for cooling between thevarious stages of the compressor. Note that the number of stagesnecessary to achieve the desired level of compression (pressure) dependson the inlet/outlet pressure ratio. Such determinations are readilyapparent (determinable) to those skilled in the art. The degree ofcompression at this stage of the process (prior to the cooling of thestream) will depend in part upon the configuration of the carbon dioxideseparation unit (4). More specifically, when the carbon dioxideseparation unit (4) does not include a compressor, the process stream(1) will be compressed to a pressure equal to or greater than 35 barprior to the cooling in the heat exchanger (3) of the present process asdepicted in FIG. 1. However, when the carbon dioxide separation unit (4)does include a compressor as a component of the carbon dioxideseparation unit (4) which allows for the process stream (1) to becompressed either prior to or as a part of the actual separation andpurification steps within the carbon dioxide separation unit (4), thenonly partial compression or no compression will take place prior to thecooling step in the heat exchange (3) of the present process (therebymaking the compression of the process stream (1) optional before beingintroduced into the carbon dioxide separation unit (4). The intent is tohave a process steam (1) that is at a pressure equal to or greater than35 bar while being treated in the carbon dioxide separation unit (4).More specifically, in order to accomplish this degree of compression,the process stream (1) may be compressed in a variety of manners. Forexample, the process stream (1) may be compressed in whole (to equal toor greater than 35 bar) or in part (compression to a pressure less than35 bar in compressor (2) but when further compressed downstream (in acompressor that is a component of the carbon dioxide separation unit(4)) achieves a level of compression that is equal to or greater than 35bar) provided that the final pressure of the process stream (1) is equalto or greater than 35 bar. For example, for a process stream (1) that isat a pressure of 20 bar, it may be possible to increase the pressure inthe compressor (2) to 30 bar prior to the cooling of the stream in theheat exchanger (3) and then raise the pressure to 37 bar in thecompressor that is a component of the carbon dioxide separation unit(4). Preferably, the process stream (1) is compressed to above 50 barwhile being treated in the carbon dioxide separation unit (4). Most ofthe compression, if not all, is preferably accomplished in thecompressor (2) prior to cooling (before being introduced into the carbondioxide separation unit (4)). Those skilled in the art will recognizethat the addition compressor (not shown) while being a part of thecarbon dioxide separation unit (4) will for practical reasons, typicallybe positioned outside of the cold box of the carbon dioxide separationunit (4) (separated from those components that are typically at lessthan ambient temperature). In addition to the options of the processstream (1) being compressed to the desired pressure, or being partiallycompressed to the desired pressure (and further compressed in the carbondioxide separation unit (4)), or not being compressed (and being fullycompressed in the carbon dioxide separation unit (4)), those skilled inthe art will recognize that in certain instances, it may be desirable toutilize/treat a portion or fraction of the process stream (1) while inother instances it may be desirable to utilize/treat the entire processstream (1). Accordingly, when compression takes place, only thatfraction that will be utilized/treated will typically be compressed.

Prior to being optionally compressed, the process stream (1) mayoptionally be passed through one or more filters, including a series offilters (not shown) in order to remove any adsorbent that may havepassed through from the process unit (0). Those skilled in the art willrecognize that a variety of different types of filters may be utilizedto filter the process stream, including, but not limited to, ceramicfilters, baghouses, metallic filters etc.

The optionally compressed process stream (1) (or portion thereof) isthen subjected to cooling to a temperature that is equal to or less than−10° C. by subjecting the process stream (1) to heat exchange in a heatexchanger (3). Those skilled in the art will recognize that while theheat exchanger (3) of FIG. 1 is positioned outside of the carbon dioxideseparation unit (4), this heat exchanger (3) for all practical purposesis considered to be a part of the carbon dioxide separation unit (4). Ina preferred embodiment, the process stream (1) is cooled to atemperature that is equal to or less than −30° C. Any type of heatexchanger (3) that is known in the art may be utilized to cool theprocess stream (1) to the desired temperature.

The next step of the process involves the separation and purification ofthe cooled process stream (1) in a carbon dioxide separation unit (4) toproduce a carbon dioxide rich liquid stream (6) and a carbon dioxidelean non-condensable stream (5). The carbon dioxide separation unit (4)may be any unit which is capable of separating/purifying carbon dioxidefrom a stream that contains carbon dioxide at a temperature that isequal to or less than −10° C., preferably equal to or less than −40° C.In other words, the carbon dioxide separation occurs at sub-ambienttemperatures and conditions. Those of ordinary skill in the artrecognize that such sub-ambient separation/purification is known in theart. Accordingly, the present process is not meant to be limited by thecarbon dioxide separation unit (4) or the process for carrying out theseparation/purification in the carbon dioxide separation unit (4). Asused throughout with regard to the present invention, the phrase “carbondioxide separation unit” refers not only to the liquefaction unitsand/or distillation columns included therein, but also to all of theadditional components that typically are considered to make up a carbondioxide separation unit (4), including, but not limited to, one or morecomponents selected from additional heat exchangers, additionalcompressors, dryers, etc. With regard to the present carbon dioxideseparation unit (4), the separation/purification is typically carriedout utilizing single or multi-step partial liquefaction as depicted inFIG. 2 which includes one liquefaction unit (14); single or multi-steppartial liquefaction in combination with at least one distillationcolumn as depicted in FIG. 3 which includes two liquefaction units (afirst liquefaction unit 14.1 and a second liquefaction unit 14.2) andone distillation column (24); and single or multi-step partialliquefaction in combination with at least one distillation column and atleast one compressor and/or heat exchanger as depicted in FIG. 4 whichincludes two liquefaction units (a first liquefaction unit 14.1 and asecond liquefaction unit 14.2), one distillation column (24), onecompressor (25) and one heat exchanger (26). When two or moreliquefaction units (14) are included in the carbon dioxide separationunit (4), those skilled in the art will recognize that liquefactionwithin each of these units may take place at the same temperature (withdifferent pressures) or at different temperatures (with the samepressure). In any event, the temperature for such liquefaction willgenerally be between about −10° C. and −57° C., preferably between about−30° C. and −57° C. In addition, note that with regard to FIG. 4, whilethe compressor (25) and heat exchanger (26) are outside of the box (4)which denotes the carbon dioxide separation unit (4), they are stillconsidered to be a part of the carbon dioxide separation unit (4) andare simply included where they are for feasibility purposes (outside ofthe cold box).

As a result of the separation/purification that takes place in thecarbon dioxide separation unit (4), there is produced a carbon dioxidelean non-condensable stream (5) and a carbon dioxide rich liquid stream(6). The carbon dioxide rich liquid stream (6) is withdrawn from thecarbon dioxide separation unit (4) as a product stream and directed forfurther use. In addition, note that while cooling in the heat exchanger(26) of the carbon dioxide separation unit (4) can be accomplishedutilizing an external coolant such as ammonia, the carbon dioxide richliquid stream (6) may also be used, prior to the stream being withdrawnfrom the carbon dioxide separation unit (4), to provide cooling withinthe heat exchanger (26) of the carbon dioxide separation unit (4). Thoseof ordinary skill in the art will recognize that such streams (6) willtypically include from about 90% to more than 99.9% carbon dioxide andmay be used for enhanced oil recovery, industrial uses, sequestration ingeological formations, etc. This carbon dioxide rich liquid stream (6)can be utilized as a liquid or may be vaporized to produce a carbondioxide rich gas stream.

The carbon dioxide non-condensable stream (5) that is withdrawn from thecarbon dioxide separation unit is typically at a high or medium pressuresince the process stream (1) treated in the carbon dioxide separationunit (4) will be at a pressure that is equal to or greater than 35 bar.As used herein with regard to the carbon dioxide non-condensable stream(5), the phrase “high pressure” refers to a pressure that ranges fromabout 50 bar to about 100 bar, preferably from about 50 bar to about 80bar. As used herein with regard to the carbon dioxide non-condensablestream (5), the phrase “medium pressure” refers to a pressure thatranges from about 10 bar to about 49 bar, preferably from about 25 barto about 49 bar.

Once the carbon dioxide lean non-condensable stream (5) is withdrawnfrom the carbon dioxide separation unit (4), it is passed through ahydrogen selective membrane separation unit (7) where the hydrogenpasses through the hydrogen selective membrane to form a hydrogen richpermeate stream (8). As used herein with regard to the hydrogen richpermeate stream (8), the phrase “hydrogen rich” refers to the permeatestream having a percentage of hydrogen that is greater than thepercentage of the other components in the hydrogen rich permeate stream(8). The hydrogen selective membrane preferentially permeates hydrogenover carbon monoxide, carbon dioxide and methane as well as any othercomponents in the stream being subjected to the hydrogen selectivemembrane. In the preferred embodiment of the present process, thehydrogen selective membrane utilized has a hydrogen permeability that isat least 1.25, preferably 5, more preferably 8 and even more preferably12, times that of the gas or gases from which the hydrogen is separatedunder the chosen operating conditions. Fluid permeation through apolymeric membrane can be described as the overall mass transport of afluid species across the membrane, where the fluid species is introducedas feed at a higher pressure than the pressure on the opposite of themembrane, which is commonly referred to as the permeate side of themembrane. Typically in a separation process, the fluid species is amixture of several components, at a minimum two, with the membraneexhibiting a higher selectivity for one component (for example“component A”) over the other component (for example “component B”).Component A permeates faster than component B, therefore relative to thefeed, the permeate is enriched in component A and the portion of thefeed that does not permeate, commonly referred to as the retentate orresidue is enriched in component B. With regard to this particularinvention, the fluid is in a gaseous form and the polymeric continuousphase of the active membrane layer is nonporous. By “nonporous” it ismeant that the continuous phase is substantially free of cavities orpores formed in a network through which migrating components of the gasmixture may flow from the feed to the permeate side of the membrane.

Transmembrane rate of transport of migrating components through thepolymeric continuous phase is commonly referred to as flux and is drivenprimarily by molecular solution/diffusion mechanisms. Preferably, thepolymer is selectively gas permeable to the components, meaning that thegases to be separated from each other permeate the membrane at differentrates. That is, a highly permeable gas will travel a distance throughthe continuous phase faster than will a less permeable gas. Theselectivity of a gas permeable polymer is the ratio of thepermeabilities of the individual component gases, e.g. Permeability ofcomponent A to permeability of component B. Hence, the greater thedifference between transmembrane fluxes of individual components, thelarger will be the component pair selectivity of a particular polymericmembrane.

With regard to the present process, the permeate stream that is obtainedwill generally contain from about 40% to about 90% hydrogen with theremaining part of the permeate stream comprising the other componentscontained in the carbon dioxide non-condensable stream (5). Accordingly,a “hydrogen rich” permeate stream will generally contain greater than orequal to 40% hydrogen, preferably up to or greater than 90% hydrogen. Inan alternative embodiment of the present process, the carbon dioxidenon-condensable stream (5) can be treated in the hydrogen selectivemembrane separation unit (7) at low pressure in order to increase therecovery of hydrogen. As used herein with regard to the carbon dioxidenon-condensable stream (5), the phrase “low pressure” refers to apressure that is equal to or less than 10 bar, preferably from aboutequal to or less than 1 bar absolute to less than 10 bar. Note that whenthe carbon dioxide non-condensable stream (5) is permeated at lowpressure, the carbon dioxide non-condensable stream (5) pressure isreduced (as it will be at high to medium pressure) by any method knownin the art such as one or more valves, a turbine, etc. (not shown). In astill further embodiment, the hydrogen rich permeate stream (8) ispermeated at the same pressure as the feed gas (15) of the process unit(0).

The remaining components in the carbon dioxide lean non-condensablestream (5) form a hydrogen lean residue stream (9). As used herein withregard to the hydrogen lean residue stream (9), the phrase “hydrogenlean” refers to the residue stream having a percentage of hydrogen thatis less than that in the carbon dioxide non-condensable sream (5).

The hydrogen selective membrane separation unit (7) utilized in theprocess of the present invention contains at least one membrane that isselective for hydrogen over the other components in the carbon dioxidelean non-condensable stream (5). Note that the target molecule, in thiscase hydrogen, determines how the permeate stream is used. With regardto each of the membranes utilized in the present process, each membranehas a permeate side (7.1) and a residue side (7.2). Since the membraneis selective for hydrogen, it allows for the passing of hydrogen throughthe membrane to the permeate side (7.1) of the membrane. While a varietyof different types of membranes may be utilized in the hydrogenselective membrane separation unit (7) of the process of the presentinvention, the preferred membrane is a polymeric membrane that isselective for hydrogen that is selected from one or more polyamides,polyaramides, polybenzimidazoles, polybenzimidazole blends withpolyimides, polyamides/imides. Hydrogen selective membranes will have aH₂/CO₂ selectivity given by the ratio of H₂ permeance to the CO₂permeance at the operating conditions that is greater than 1.25,preferably greater than 5, more preferably greater than 8. In apreferred embodiment of the present invention, the polymeric membranesof the first hydrogen selective membrane separation unit (4) and thesecond hydrogen selective membrane separation unit (11) will be made ofthe same polymeric materials.

The hydrogen selective membranes of the present invention can befabricated into any membrane form by any appropriate conventionalmethod. For example, the hydrogen selective membranes may be cast as asheet at the desired thickness onto a flat support layer (for flat sheetmembranes), or extruded through a conventional hollow fiber spinneret(for hollow fiber membranes). Processes for preparing uniformly densemembranes or asymmetric membranes are also available and known to thoseskilled in the art. In addition, it is possible to prepare compositemembranes by casting or extruding the membrane over a porous support ofanother material in either flat film or hollow fiber form. Theseparating layer of the composite membrane can be a dense ultra-thin orasymmetric film. In the preferred embodiment of the present process, thehydrogen selective membranes are in the form of modules comprisingmembranes formed as either hollow fibers or spiral wound asymmetric flatsheets.

The hydrogen selective membrane separation unit (7) includes at leastone of the above noted membranes. With regard to the actualconfiguration of the hydrogen selective membrane separation unit (7),the hydrogen selective membrane separation unit (7) can take on anynumber of configurations. In one embodiment, there is only one membraneelement in the hydrogen selective membrane separation unit (7). In analternative embodiment, the hydrogen selective membrane separation unit(7) comprises a series of hydrogen selective membrane elements within asingle membrane housing (not shown). With regard to this embodiment, theseries of hydrogen selective membranes can be made up of hydrogenselective membranes of the same type selected from the hydrogenselective membranes detailed above or of two or more different hydrogenselective membranes selected from the hydrogen selective membranesdetailed above. In the embodiment where there are two or more hydrogenselective membranes, the hydrogen selective membranes will preferably beof the same type and the same fabrication (for example, sheets orfibers). In a still further embodiment concerning the configuration ofthe hydrogen selective membrane separation unit (7), the hydrogenselective membrane separation unit (7) comprises two or more membranehousings with each of the housings having one or more hydrogen selectivemembranes as described hereinbefore. More specifically, in thisembodiment, there can be two or more membrane housings, with each of thehousings having either one hydrogen selective membrane or two or morehydrogen selective membranes of the same type or two or more hydrogenselective membranes of two of more different types. The resultinghydrogen selective membranes may be mounted in any convenient type ofhousing or vessel adapted to provide a supply of the carbon dioxidenon-condensable stream (5), and removal of the permeate stream (7.1) andresidue stream (7.2). The housing also provides a high-pressure side(for the carbon dioxide non-condensable stream (5) and the residuestream) and a low-pressure side of the hydrogen selective membrane (forthe permeate stream). As an example of configurations contemplated to bewithin the present invention, flat-sheet membranes can be stacked inplate-and-frame modules or wound in spiral-wound modules. Hollow-fibermembranes can be potted with a thermoset resin in cylindrical housings.The final hydrogen selective membrane separation unit (7) comprises oneor more membrane modules or housings, which may be housed individuallyin pressure vessels or multiple elements may be mounted together in asealed housing of appropriate diameter and length.

As noted above, as a result of passing the carbon dioxidenon-condensable stream (5) through the hydrogen selective membraneseparation unit (7), two separate streams are formed—a hydrogen richpermeate stream (8) and a hydrogen lean residue stream (9). The hydrogenrich permeate stream (8) is optionally compressed in a second compressor(13) before being recycled for use as a supplemental feed stream for theprocess unit (0) or as a supplemental feed stream for other processesupstream. More specifically, in the preferred embodiment, the hydrogenrich permeate stream (8) is utilized as two separate fractions—as afirst hydrogen rich permeate fraction (8.1) to be used as a supplementalfeed stream for processes that are upstream of the process unit (0) (notshown) and as a second hydrogen rich permeate fraction (8.2) to be usedas a supplemental feed stream in the process unit (0) (not shown) withthe objective being to optimize the use of the recycle stream (8) inorder to maximize the conversion of carbon monoxide to carbon dioxideand hydrogen. With regard to this particular embodiment, the proportionof each fraction recycled to the corresponding devices (0, and what everdevice is upstream) depends upon the percentage of production (the load)from the feed gas producing unit. Those of ordinary skill in the artwill recognize that a number of different factors can contribute to thedetermination of the load including, but not limited to, the design ofthe plant and the size of the various components of the feed gasproducing unit, the process unit (0), heat exchangers, carbon dioxideremoval unit, etc. Preferably the conversion of carbon monoxide tocarbon dioxide and hydrogen is maximized utilizing a portion of therecycle stream (8.1) while the remaining portion of the recycle stream(8.2) is sent to the process unit (0). This is accomplished by firstdirecting the flow of the hydrogen rich permeate stream (8) to be addedto the stream that is to be fed into the feed gas producing unit. Theoptimum solution is to split the hydrogen rich permeate stream (8) withone part or fraction going to the feed gas producing unit and the otherpart or fraction going to the stream to be introduced into the processunit.

In a still further embodiment of the present invention, a water gasshift reactor (32) may be installed along the line transporting thehydrogen rich permeate stream (8) in order to reduce the carbon monoxidethat may be present in the stream (8). It is especially preferred toreduce the level of carbon monoxide to such a low level that there is nofurther incentive to convert the carbon monoxide contained in the stream(8), In the preferred embodiment, this water gas shift reactor (32)would be a low temperature water gas shift reactor. As used herein, thephrase “low temperature water gas shift reactor” refers to a water gasshift reaction that generally occurs in the 180 to 240° C. range tofurther reduce carbon monoxide levels compared to the higher temperaturewater gas shift reactor which generally operates in a higher temperaturerange and is utilized to convert bulk (higher percentages) of carbonmonoxide. Low temperature water gas shift reactors of the typecontemplated in the present invention are known in the art andaccordingly will not be described in great detail herein other than tonot that such reactors require proper heating means (not shown) andsteam injection (not shown). Furthermore, the size of the lowtemperature water gas shift reactor (32) will depend upon the quantityof hydrogen rich permeate (8) processed. Typically, this stream (8) willbe smaller in size than the quantity of the feed stream (15) processed.

With regard to the additional streams, while the hydrogen product stream(23) is recovered as product, as in the previous embodiments, a portionof this stream (23) can be used for hydrogen fueling of the feed gasproducing unit (31). In a still further modification to this embodiment,it is advantageous to further heat the first hydrogen rich permeatefraction (8.1) prior to this stream being added as a supplemental feedto the feed gas producing unit.

In the next step of the present process, the hydrogen lean residuestream (9) is passed through a carbon dioxide selective membraneseparation unit (10) in order to form a carbon dioxide enriched permeatestream (11). As used herein with regard to the carbon dioxide enrichedpermeate stream (11), the phrase “carbon dioxide enrich” refers to thepermeate stream having a percentage of carbon dioxide that is greaterthan the percentage of the other components in the carbon dioxideenriched permeate stream (11). The carbon dioxide selective membrane ofthe carbon dioxide selective membrane separation unit (10) is used topreferentially permeate carbon dioxide over carbon monoxide, methane andnitrogen as well as any other components in the stream being subjectedto the carbon dioxide selective membrane. In the preferred embodiment ofthe present process, the carbon dioxide selective membrane utilized hada carbon dioxide permeability that is more than 5 times, preferablygreater than 10 times and even more preferably greater than 20 timesthat of the gas or gases from which the carbon dioxide is separatedunder the chosen operating conditions, with the exception of hydrogen.

The remaining components in the hydrogen lean residue stream (9) form acarbon dioxide depleted residue stream (12). As used herein with regardto the carbon dioxide depleted residue stream (12), the phrase “carbondioxide depleted” refers to the residue stream having a percentage ofcarbon dioxide that is less than that in the stream introduced into thecarbon dioxide membrane separation unit (10) (the hydrogen lean residuestream (9)).

The carbon dioxide selective membrane separation unit (10) utilized inthe process of the present invention contains at least one membrane thatis selective for carbon dioxide over the other components in thehydrogen lean residue stream (9). Note that the target molecule, in thiscase carbon dioxide, determines how the permeate stream is used. Withregard to each of the membranes utilized in the present process, eachcarbon dioxide selective membrane has a permeate side (10.1) and aresidue side (10.2). Since the membrane is selective for carbon dioxide,it allows for the passing of carbon dioxide through the membrane to thepermeate side (10.1) of the membrane.

While a variety of different types of membranes may be utilized in thecarbon dioxide selective membrane separation unit (10) of the process ofthe present invention, the preferred membrane is a polymeric membranethat is selective for carbon dioxide that is selected from one or morepolyimides, polyetherimides polysulfone, polyethersulfones,polyarylsulfone, polycarbonate, tetrabromo-bisphenol A polycarbonate,tetrachloro-bisphenol A polycarbonate, polydimethylsiloxane, naturalrubber, cellulose actetate, cellulose triacetate, ethyl cellulose,PDD-TFE and polytriazole.

With regard to each of the carbon dioxide selective membranes utilizedin the carbon dioxide selective membrane separation unit (10) of thepresent process, each carbon dioxide selective membrane has a permeateside (10.1) and a residue side (10.2). Since the membrane is selectivefor carbon dioxide, it allows for the passing of carbon dioxide throughthe membrane to the permeate side (10.1) of the membrane. While themembrane is selective for carbon dioxide, those skilled in the art willrecognize that a minor portion of the other components in the hydrogenlean residue stream (9) will also pass through the carbon dioxideselective membrane to become a part of the permeate. Accordingly, withregard to the present process, the permeate stream that is obtained willgenerally contain from about 40% to about 90% carbon dioxide with theremaining part of the permeate stream comprising the other componentscontained in the hydrogen lean residue stream (9). As a result ofpassing the hydrogen lean residue stream (9) into the carbon dioxideselective membrane separation unit (10) and through the membrane, thisstream is separated into two streams—one which is considered to becarbon dioxide enriched and one which is considered to be carbon dioxidedepleted.

While a variety of different types of membranes may be utilized in thecarbon dioxide selective membrane separation unit (10) of the process ofthe present invention, the preferred membrane is made of any number ofpolymers that are suitable as membrane materials. With regard to themembranes of the present invention, these polymers include, but are notlimited to, substituted or unsubstituted polymers selected frompolysiloxane, polycarbonates, silicone-containing polycarbonates,brominated polycarbonates, polysulfones, polyether sulfones, sulfonatedpolysulfones, sulfonated polyether sulfones, polyimides and arylpolyimides, polyether imides, polyketones, polyether ketones, polyamidesincluding aryl polyamides, poly(esteramide-diisocyanate),polyamide/imides, polyolefins such as polyethylene, polypropylene,polybutylene, poly-4-methyl pentene, polyacetylenes,polytrimethysilylpropyne, fluorinated polymers such as those formed fromtetrafluoroethylene and perfluorodioxoles, poly(styrenes), includingstyrene-containing copolymers such as acrylonitrile-styrene copolymers,styrene-butadiene copolymers and styrene-vinylbenzylhalide copolymers,cellulosic polymers, such as cellulose acetate-butyrate, cellulosepropionate, ethyl cellulose, methyl cellulose, cellulose triacetate, andnitrocellulose, polyethers, poly(arylene oxides) such as poly(phenyleneoxide) and poly(xylene oxide), polyurethanes, polyesters (includingpolyarylates), such as poly(ethylene terephthalate), and poly(phenyleneterephthalate), poly(alkyl methacrylates), poly(acrylates),polysulfides, polyvinyls, e.g., poly(vinyl chloride), poly(vinylfluoride), poly(vinylidene chloride), poly(vinylidene fluoride),poly(vinyl alcohol), poly(vinyl esters) such as poly(vinyl acetate) andpoly(vinyl propionate), poly(vinyl pyridines), poly(vinyl pyrrolidones),poly(vinyl ketones), poly(vinyl ethers), poly(vinyl aldehydes) such aspoly(vinyl formal) and poly(vinyl butyral), poly(vinyl amides),poly(vinyl amines), poly(vinyl urethanes), poly(vinyl ureas), poly(vinylphosphates), and poly(vinyl sulfates), polyallyls,poly(benzobenzimidazole), polyhydrazides, polyoxadiazoles,polytriazoles: poly(benzimidazole), polycarbodiimides, polyphosphazines,and interpolymers, including block interpolymers containing repeatingunits from the above such as terpolymers of acrylonitrile-vinylbromide-sodium salt of para-sulfophenylmethallyl ethers, and grafts andblends containing any of the foregoing. The polymer suitable for use isintended to also encompass copolymers of two or more monomers utilizedto obtain any of the homopolymers or copolymers named above. Typicalsubstituents providing substituted polymers include halogens such asfluorine, chlorine and bromine, hydroxyl groups, lower alkyl groups,lower alkoxy groups, monocyclic aryl, lower acyl groups and the like.

With regard to one embodiment of the present invention, the preferredpolymers include, but are not limited to, polysiloxane, polycarbonates,silicone-containing polycarbonates, brominated polycarbonates,polysulfones, polyether sulfones, sulfonated polysulfones, sulfonatedpolyether sulfones, polyimides, polyetherimides, polyketones, polyetherketones, polyamides, polyamide/imides, polyolefins such as poly-4-methylpentene, polyacetylenes such as polytrimethysilylpropyne, andfluoropolymers including fluorinated polymers and copolymers offluorinated monomers such as fluorinated olefins and fluorodioxoles, andcellulosic polymers, such as cellulose diacetate and cellulosetriacetate. Examples of preferred polyimides are Ultem 1000, P84 andP84-HT polymers, and Matrimid 5218.

Of the above noted polymeric membranes, the most preferred membranes arethose made of polyimides. More specifically, polyimides of the typedisclosed in U.S. Pat. No. 7,018,445 and U.S. Pat. No. 7,025,804, eachincorporated herein in their entirety by reference. With regard to thesetypes of membranes, the process of the present invention preferablyutilizes a membrane comprising a blend of at least one polymer of a Type1 copolyimide and at least one polymer of a Type 2 copolyimide in whichthe Type 1 copolyimide comprises repeating units of formula I

in which R₂ is a moiety having a composition selected from the groupconsisting of formula A, formula B, formula C and a mixture thereof,

Z is a moiety having a composition selected from the group consisting offormula L, formula M, formula N and a mixture thereof; and

R₁ is a moiety having a composition selected from the group consistingof formula Q, formula S, formula T, and a mixture thereof,

in which the Type 2 copolyimide comprises the repeating units offormulas IIa and IIb

in which Ar is a moiety having a composition selected from the groupconsisting of formula U, formula V, and a mixture thereof,

in whichX, X₁, X₂, X₃ independently are hydrogen or an alkyl group having 1 to 6carbon atoms, provided that at least two of X, X₁, X₂, or X₃ on each ofU and V are an alkyl group,Ar′ is any aromatic moiety,R_(a) and R_(b) each independently have composition of formulas A, B, C,D or a mixture thereof, and

Z is a moiety having composition selected from the group consisting offormula L, formula M, formula N and a mixture thereof

The material of the membrane consists essentially of the blend of thesecopolyimides. Provided that they do not significantly adversely affectthe separation performance of the membrane, other components can bepresent in the blend such as, processing aids, chemical and thermalstabilizers and the like.

In a preferred embodiment, the repeating units of the Type 1 copolyimidehave the composition of formula Ia.

Wherein R₁ is as defined hereinbefore. A preferred polymer of thiscomposition in which it is understood that R₁ is formula Q in about 16%of the repeating units, formula S in about 64% of the repeating unitsand formula T in about 20% of the repeating units is available from HPPolymer GmbH under the tradename P84

In another preferred embodiment, the Type 1 copolyimide comprisesrepeating units of formula Ib.

Wherein R₁ is as defined hereinbefore. Preference is given to using theType 1 copolyimide of formula Ib in which R₁ is a composition of formulaQ in about 1-99% of the repeating units, and of formula _(s) in acomplementary amount totaling 100% of the repeating units.

In yet another preferred embodiment, the Type 1 copolyimide is acopolymer comprising repeating units of both formula Ia and Ib in whichunits of formula Ib constitute about 1-99% of the total repeating unitsof formulas Ia and Ib. A polymer of this structure is available from HPPolymer GmbH under the tradename P84-HT325.

In the Type 2 polyimide, the repeating unit of formula IIa should be atleast about 25%, and preferably at least about 50% of the totalrepeating units of formula IIa and formula IIb. Ar′ can be the same asor different from Ar.

The polyimides utilized to form the membranes of the present processwill typically have a weight average molecular weight within the rangeof about 23,000 to about 400,000 and preferably about 50,000 to about280,000.

The carbon dioxide selective membranes of the present process can befabricated into any membrane form by any appropriate conventional methodas noted hereinbefore with regard to the hydrogen selective membranes(i.e., flat sheet membranes or hollow fiber membranes). While the carbondioxide selective membranes do not have to be in the same form as thehydrogen selective membranes, in one preferred embodiment, the form ofthe carbon dioxide selective membranes is in the hollow fiber form andthe hydrogen selective membranes are in the same form.

As with the hydrogen selective membrane separation unit (7), the carbondioxide membrane separation unit (10) includes at least one of the abovenoted membranes. With regard to the actual configuration of the carbondioxide selective membrane separation unit (10), the carbon dioxideselective membrane separation unit (10) can take on any number ofdifferent configurations as discussed hereinbefore with regard to thehydrogen selective membrane separation unit (7).

As noted, as a result of passing the hydrogen lean residue stream (9)through the carbon dioxide selective membrane separation unit (10), twoseparate streams are formed—a carbon dioxide enriched permeate stream(11) and a carbon dioxide depleted residue stream (12) wherein theenrichment and depletion of carbon dioxide is with reference to the feedstream fed to the carbon dioxide selective membrane separation unit(10). The carbon dioxide enriched permeate stream (11) may be furtherutilized in a variety of manners. More specifically, the carbon dioxideenriched permeate stream (11) may be recycled to the process stream (1)from the process unit (0) where is it added to the process stream (1)prior to the compressor (2) (as shown in FIG. 1) or within thecompressor (2) between two of the stages of compression (not shown inFIG. 1) or optionally compressing the carbon dioxide enriched permeatestream (11) and recycling the optionally compressed carbon dioxideenriched permeate stream (11) to be used as a supplemental feed streamin other processes such as a supplemental feed stream for a water gasshift reactor in a hydrogen production plant. The carbon dioxideenriched permeate stream (11) may also be recycled directly back to thecarbon dioxide separation unit (4) for further processing.

The carbon dioxide depleted residue stream (12) that is obtained fromthe carbon dioxide selective membrane separation unit (10) can bewithdrawn for further use. For example, the carbon dioxide depletedresidue stream (12) can be used as a fuel (for example as a steammethane reformer fuel), as a feed stream (for example as a steam methanereformer feed stream) or as both a fuel and a feed stream in otherprocesses such as in a hydrogen generation plant. In addition, thecarbon dioxide depleted residue stream (12) can be used to regenerateany dryers that may be positioned within the process schematic of thepresent invention to remove moisture, thereby increasing the efficiencyof carbon dioxide removal in the carbon dioxide separation unit (4) atlower temperatures.

The operating temperatures for the hydrogen selective membranes and thecarbon dioxide selective membranes are each independently selected basedon the physical properties of each membrane such that it is mechanicallystable and a sufficient gas flux can be maintained across the membrane.Typically, the stream being fed to each of the membrane separation units(7, 10) will be heated or cooled, if necessary, to a temperature whichranges from about −55° C. to about 150° C. In other words, the processof membrane separation in each of these units (7, 10) typically operatesat the noted temperature. In one alternative, the hydrogen lean residestream (9) is fed into the carbon dioxide selective membrane unit (10)at low to sub-ambient temperatures, preferably from −55° C. to about 30°C., preferably from −55° C. to about 10° C. In such cases, the carbondioxide selective membranes are cold membranes. In still anotheralternative, the carbon dioxide lean non-condensable stream (5) from thecarbon dioxide separation unit (4) is fed to the hydrogen selectivemembrane separation unit (7) after being heated to a temperature fromabout 50° C. to about 150° C. in an optional heat exchanger 28. Withregard to this particular alternative, the heat brought to the carbondioxide lean non-condensable stream (5) is taken from the process stream(1) after the step of compression.

In an even further still embodiment of the present invention, it is alsopossible to incorporate an optional water gas shift reactor (33) justprior to the hydrogen and carbon dioxide membrane units (7, 10) in orderto further convert any carbon monoxide presenting the carbon dioxidelean non-condensable stream (5). As with the optional water gas shiftreactor located along the hydrogen rich permeate stream (8), this watergas shift reactor (33) would also preferably be a low temperature watergas shift reactor as described hereinbefore. The size of the lowtemperature water gas shift reactor (33) would depend upon the amount ofthe carbon dioxide lean non-condensable stream (5) being processed. Notethat when this option is utilized, the membranes utilized in thehydrogen and carbon dioxide membrane units (7, 10) will be designed toaddress wet syngas.

While the preferred embodiments would be to place the optional water gasshift reactor (32 or 33) along the permeate line (8) or after the carbondioxide separation unit (4) and just prior to the hydrogen and carbondioxide membranes (7, 10) respectively, in a still further embodiment,it would be possible to place a low temperature water gas shift reactor(not shown) just prior to the process unit (0) to treat the feed gas(15).

Additional embodiments of the present invention are depicted in FIGS. 5to 7. These embodiments relate to a process for producing hydrogen in ahydrogen generation plant from a hydrocarbon containing feed stream (16)(preferably natural gas) and capturing at least 80%, preferably at least90%, even more preferably at least 99%, and further still approaching orobtaining 100% capture, of the overall emissions of carbon dioxide ofthe feed gas producing unit (31) utilizing a carbon dioxide separationunit and two membrane separation units. More specifically, in theprocess of the present invention, the process can be executed in avariety of manners including utilizing a feed gas producing unit (31), apressure swing adsorption unit (0), a carbon dioxide separation unit(4), a hydrogen selective membrane separation unit (7) and a carbondioxide selective membrane separation unit (10). As noted previouslyherein, the phrase “feed gas producing unit” refers to any unit whichproduces a feed gas that can be subjected to treatment for the removalof hydrogen. More specifically, the feed gas (15) may be a feed gas (15)from a reformer unit/water gas shift unit, a POx unit, an ATR unit,syngas from a coal gasification unit, refinery off gas or any other gasmixture that contains hydrogen, carbon monoxide and carbon dioxide ascomponents in the gas mixture. The present process is preferablyexecuted in a variety of manners including: A) using one or morepre-reformers (17), a steam methane reformer (19), a water gas shiftreactor (21), a pressure swing adsorption unit (0), a carbon dioxideseparation unit (4), a hydrogen selective membrane separation unit (7)and a carbon dioxide selective membrane separation unit (10) or B) asteam methane reformer (19), a water gas shift reactor (21), a pressureswing adsorption unit (0), a carbon dioxide separation unit (4), ahydrogen selective membrane separation unit (7) and a carbon dioxideselective membrane separation unit (10). With regard to these preferredembodiments, a hydrocarbon containing feed stream (16) is optionallypre-reformed in at least one pre-reformer (17) to form a pre-reformedgas stream (18). Pre-reforming is carried out in those cases where it isconsidered to be advantageous to reform the heavier hydrocarbons in thehydrocarbon containing feed stream (16) thereby reducing cracking on thecatalyst in the main steam methane reformer (19) and preventingexcessive heat rise in the main reformer. The present process is notmeant to be limited by the type of pre-reformer (17) utilized forcarrying out the process of the present invention. Accordingly, anypre-reformer (17) that is known in the art may be used in the process ofthe present invention. The pre-reformer (17) can be a single highpressure (typically from about 25 to about 30 bar) adiabatic vesselwhere desulfurized natural gas preheated to around 600° C. is fed to abed filled with pre-reforming catalyst (typically catalyst with a highnickel content). Such vessels typically have an outlet temperaturearound 400° C. The pre-reformer (17) can also be a series of at leasttwo adiabatic pre-reformers (17) with heating in between the vessels inorder to provide additional benefits by minimizing the amount of fuelrequired and thus the amount of hydrogen to fuel. The advantage of suchpre-reformers (17) is that the overall need for fuel to provide directheat to the reforming reaction is reduced, hence naturally decreasingcarbon dioxide production in the plant (leading to the high overallcarbon dioxide recovery). In addition, the pre-reformer (17) may beoperated in the same manner that is known in the art utilizing generalconditions, including temperatures and pressures.

The next step of the preferred process involves reforming thepre-reformed gas stream (18) (or in the case where there is nopre-reforming, the hydrocarbon containing gas stream (16)) in a steammethane reformer unit (19) in order to obtain a syngas stream (20). Aswith the pre-reformer (17), the present invention is not meant to belimited by the steam methane reformer unit (19) or the process forcarrying out the reaction in the steam methane reformer unit (19).Accordingly, any steam methane reformer unit (19) known in the art maybe used in the process of the present invention. By way of generaldescription, with regard to the steam methane reformer unit (19) of FIG.5, the pre-reformed gas stream (18) (or hydrocarbon containing gasstream (16)) will be combined with high pressure steam (not shown inFIG. 5) before entering the steam methane reforming unit (19). Suchsteam methane reformer units (19) typically contain tubes (not shown)packed with catalyst (typically a nickel catalyst) through which thesteam and gas stream (18) mixtures passes. An elevated temperature ofabout 860° C. is typically maintained to drive the reaction which isendothermic. As used throughout with regard to the present invention,the phrase “steam methane reformer unit” refers not only to the actualreformer units, but also to all of the additional components thattypically are considered to make up a steam methane reformer, including,but not limited to, one or more components selected from heatexchangers, the reformer, tubes with one or more types of catalyst, etc.Prior to be introduced into the actual reformer of the steam methanereformer (19), the stream to be treated will typically be compressed,e.g. to about 200 to 600 psig, and combined with the steam as describedhereinbefore. In those instances where pre-reforming is utilized, thestream to be pre-reformed will typically be compressed to e.g., about200 to 600 psig, thereby resulting in a pre-reformed gas stream (18)which does not require further compression before being introduced intothe steam methane reformer (19). The reaction product from the steammethane reformer unit (19) is principally a hydrogen rich effluent thatcontains hydrogen, carbon monoxide, methane, water vapor and carbondioxide in proportions close to equilibrium amounts at the elevatedtemperature and pressure. This effluent is referred to as the syngasstream (20) in the present process.

Once the reforming is carried out, the resulting syngas stream (20) issubjected to a shift reaction in a water gas shift reactor (21) in orderto obtain a feed gas (15). The syngas stream (20) is subjected to ashift reaction due to the high amount of carbon monoxide that is oftenpresent due to the steam methane reforming (the amount of carbonmonoxide actually depends upon the composition of the initial streaminjected into the steam methane reformer unit (19)). The water gas shiftreactor (21) functions to form additional hydrogen and carbon dioxide byfurther reacting or treating the syngas stream (20) in order to obtain afeed gas (15) for the process unit (0). The syngas stream (20) isintroduced into the water gas shift reactor (21) (which can contain avariety of stages or one stage; various stages not shown) along withsteam (not shown) to form additional hydrogen and carbon dioxide. Thewater gas shift reactor (21) converts the carbon monoxide to carbondioxide with the liberation of additional hydrogen by reaction at hightemperature in the presence of the additional steam. Such reactors (21)typically operate at a temperature from about 200° C. to about 500° C.In some cases the stream from the steam methane reformer (19) will be ata higher temperature so optionally the stream may first be cooled with aheat exchanger (typically a steam generator—not shown) before beingpassed through the water gas shift reactor (21). In a preferredalternative, the water gas shift reactor (21) is a multiple stage watergas shift reactor which includes high temperature shift (typically about371° C. or above), medium temperature shift (typically around 288° C.),low temperature shift (typically about 177° C. to 204° C.) or anycombination thereof. Such multiple stage water gas shift reactors areknown and are used to concentrate the amount of carbon dioxide in theresulting gas stream by the manner in which the shifts are arranged(with the high temperature shift resulting in less carbon monoxidereaction and the low temperature shift resulting in more carbon monoxidereaction).

The feed gas (15) from the water gas shift reactor (21) is thensubjected to the process as described hereinbefore involving a processunit (0), a carbon dioxide separation unit (4), a hydrogen selectivemembrane separation unit (7), and a carbon dioxide membrane separationunit (10), each as described hereinbefore.

In this particular embodiment, the feed gas (15) is introduced into theprocess unit (0) (in this particular case a pressure swing adsorptionunit) where it undergoes pressure swing adsorption to produce a hydrogenproduct stream (23) and a process stream (1). While the hydrogen productstream (23) is recovered as product, a portion of this stream (23) canbe used for hydrogen fueling of the steam methane reformer (19). Theprocess stream (1) is further treated in the carbon dioxide separationunit as described hereinbefore. As noted previously, the process stream(1) may optionally be completely compressed in the compressor (2) orpartially compressed in the compressor (2) or completely compressed inan additional compressor that forms a part of the carbon dioxideseparation unit (4) or partially compressed in an additional compressorthat forms a part of the carbon dioxide separation unit (4) as describedhereinbefore. The process stream (1) is cooled in the heat exchanger (3)prior to the separation/purification steps of the carbon dioxideseparation unit (4). As a result of treating the process stream (1) inthe carbon dioxide separation unit (4), a carbon dioxide rich liquidstream (which can be vaporized) is produced. This stream is withdrawnfrom the carbon dioxide separation unit (4) where it can be used asproduct. The remaining components from the process stream (1) form acarbon dioxide lean non-condensable stream (5) which is then passedthrough a hydrogen selective membrane separation unit (7) therebyforming a hydrogen rich permeate stream (8) and a hydrogen lean residuestream (9). As noted in the previously described process of FIG. 1, thehydrogen rich permeate stream (8) may be optionally compressed in acompressor (13) and recycled to be used as supplemental feed for theprocess unit (0).

However, when the present embodiment is utilized in a hydrogengeneration plant as shown in FIG. 5, in addition to being recycled foruse as a supplemental feed for the process unit (0), the hydrogen richpermeate stream (8) may also be used as a supplemental feed stream for asteam methane reformer (19) and/or for a water gas shift reactor (21)after optionally compressing the stream (8). Accordingly, with regard tothe preferred embodiment, the hydrogen rich permeate stream (8) may berecycled as a supplemental feed for one or more of 1) the process unit(0), 2) the steam methane reformer (19) and 3) the water gas shiftreactor (21). Also, the hydrogen rich permeate stream (8) may beutilized as a supplemental fuel for a steam methane reformer (19). Inone embodiment, it is especially preferable to use the hydrogen richpermeate stream (8) as a fuel to the steam methane reformer (19) sincedoing so can boost the percentage of carbon dioxide capture. Inaddition, by doing so, it is possible to eliminate or reduce the carbondioxide emissions from the steam methane reformer (19) as the naturalgas fuel has been eliminated/minimized.

In another embodiment, the hydrogen rich permeate stream (8) can be usedas a supplemental feed for the process unit (0) with the objective ofincreasing hydrogen production. In an alternative embodiment, thehydrogen rich permeate stream (8) can be used as a supplemental feed forthe water gas shift reactor (21) with the objective of driving thereaction towards the production of more carbon dioxide and hydrogen(converting more of the carbon monoxide into carbon dioxide andhydrogen). In a still further embodiment as depicted in FIG. 6, theprocess unit (0) is a pressure swing adsorption unit (0) and thehydrogen rich permeate stream (8) is utilized as two separatefractions—as a first hydrogen rich permeate fraction (8.1) to be used asa supplemental feed stream in the water gas shift reactor (21) and as asecond hydrogen rich permeate fraction (8.2) to be used as asupplemental feed stream in the pressure swing adsorption unit (0). Forpurposes of FIG. 6, the remaining recycle streams that are noted in FIG.5 have been omitted in order to concentrate more specifically upon therecycle of the fractions (8.1, 8.2) of the hydrogen rich permeate stream(8). With regard to this particular embodiment, the objective is tooptimize the use of the recycle stream (8) in order to maximize theconversion of carbon monoxide to carbon dioxide and hydrogen while atthe same time maximizing the production of hydrogen product.

With regard to this particular embodiment, the proportion of eachfraction recycled to the corresponding devices (0, 21) depends upon thepercentage of production (the load) from the steam methane reformer(19). Those of ordinary skill in the art will recognize that a number offactors can contribute to the determination of the load for the steammethane reformer (19) including, but not limited to, the design of theplant, the size of the various components such as the steam methanereformer (19), water gas shift reactor (21), the pressure swingadsorption unit (0), heat exchangers, carbon dioxide removal unit, etc.With regard to this particular embodiment, the shift reaction ismaximized utilizing a portion of the recycle stream (8.1) while theremaining portion of the recycle stream (8.2) is sent to the pressureswing adsorption unit (0). This is accomplished by first directing theflow of the hydrogen rich permeate stream (8) to be added to the syngasstream (20) that is to be fed into the water gas shift reactor (21). Asnoted, the quantity of this first fraction (8.1) is determined by theload of the steam methane reformer unit (19). More specifically, whenthe steam methane reformer unit (19) is running at full load orcapacity, a much higher flow is being sent to the water gas shift unit(21) and consequently, a much higher flow is being sent furtherdownstream. Accordingly, for plants that are retrofitted and notspecifically designed to handle this degree of flow of recycle, theremay exist limitations on shift capacity, heat exchanger duties, etc.Therefore, in some instances, there may be limitations when the entirerecycle (8) is added prior to the water gas shift unit (21). However, itis desirable to recycle to the water gas shift reactor (21) as anultimate increase in hydrogen production can be seen (an increase of upto 15% or more). In those instances where the recycle (8) is simply sentto the stream (15) before the pressure swing adsorption unit (0), theremay still be capacity issues with regard to the actual pressure swingadsorption unit (0) and the downstream compressors. Even so, this optionis also desirable as an increase in hydrogen production can also beobtained with this option.

The optimum solution is to split the hydrogen rich permeate stream (8)with one part or fraction going to the water gas shift reactor (19) andthe other part or fraction going to the pressure swing adsorption unit(21). With regard to this embodiment, it is preferable to first directas much as possible of the flow of the recycle (8.1) to the syngasstream (20) before the water gas shift reactor (21) until the water gasshift reactor (21) reaches it maximum capacity (being determined in partby the steam methane reformer (19) load) or unit 100% of the recyclestream (8.1) is recycled to the water gas shift reactor (21) and thendirecting the remaining fraction (8.2), if any, to the pressure swingadsorption unit (0).

As used herein the phrase “steam methane reformer (19) load” refers tothe actual volume of the gas stream processed in the steam methanereformer (19) compared to the volume that the steam methane reformer(19) is capable of processing. For example, if the steam methanereformer is capable of processing 50,000 standard cubic meters ofnatural gas but only processes 45,000 standard cubic meters of naturalgas, then the load would be considered to be 90%. When the load from thesteam methane reformer unit (19) is considered to be relatively low, alarger proportion of the recycle will go to the water gas shift reactor(21) rather than to the pressure swing adsorption unit (0). Thoseskilled in the art will recognize that the load for the steam methanereformer (19) will depend upon any number of a variety of variables suchas the size of the plant, the size of the steam methane reformer (19),the size of the equipment utilized downstream, and the composition ofthe natural gas stream. Accordingly, the phrase “relatively low” whenused in terms of the steam methane reformer (19) load operated understandard conditions that are known to those skilled in the art, refersto those instances where the load with regard to the steam methanereformer (19) is, for example, less than or equal to 85%. In suchinstances, often the first hydrogen rich permeate fraction (8.1) will begreater than the second hydrogen rich permeate fraction (8.2) in termsof quantity. In other words, the first hydrogen rich permeate willcomprise greater than 50% of the total amount of the hydrogen richpermeate stream (8). Otherwise, in those instances where the steammethane reformer (19) load is greater than 85%, preferably greater than90%, the second hydrogen rich permeate stream will range from greaterthan 50% of the hydrogen rich permeate stream (8) up to 100% of thehydrogen rich permeate stream (8).

In a still further modification to this embodiment, it is advantageousto further heat the first hydrogen rich permeate fraction (8.1) prior tothis stream being added as a supplemental feed to the syngas stream ofline (20). This combined fraction (8.1) and syngas stream (20) are thenfed into the water gas shift reactor (21). While this heating may becarried out in any manner known in the art, preferably the firsthydrogen rich permeate fraction (8.1) is heated utilizing a heatexchanger (30) specifically for this permeate fraction (8.1). Inaddition to heating this first hydrogen rich permeate fraction (8.1)before adding the fraction to the syngas stream (20), steam can beinjected into this fraction (8.1) via line (29) just prior to thefraction (8.1) being mixed with the syngas stream (20). The heating ofthis first hydrogen rich permeate fraction (8.1) further improves theefficiency of the recycle. By injecting steam into this fraction (8.1),it is possible to avoid steam condensation (which is detrimental to thecatalyst in the water gas shift reactor (21)) when mixed with the syngasstream (20). In addition, by injecting steam at this point, it will bepossible to further drive the carbon monoxide shift.

Note that with regard to the hydrogen production and carbon dioxidecapture embodiments, an optional water gas shift reactor may also beutilized to shift away carbon monoxide in the hydrogen permeate stream(8) as discussed hereinbefore. Preferably such a water gas shift unit(32) would be a low temperature water gas shift unit as definedhereinbefore. In addition with regard to these embodiments, an optionalwater gas shift reactor (33) may also be utilized prior to the hydrogenand carbon dioxide membrane units (7, 10) as defined hereinbefore.Finally, a low temperature water gas shift reactor (not shown) may alsobe considered to be placed just prior to the process unit (0) to treatthe feed gas (15).

The hydrogen lean residue stream (9) is passed through the carbondioxide selective membrane separation unit (10) thereby forming a carbondioxide enrich permeate stream (11) and a carbon dioxide depletedresidue stream (12) as described hereinbefore. The carbon dioxideenriched permeate stream (11) can be recycled in a variety of mannersincluding 1) to the process stream (1) from the process unit (0) whereis it added to the process stream (1) just prior to the compressor (2)(as shown in FIG. 5) or within the compressor (2) between two of thestages of compression (not shown in FIG. 5); 2) optionally compressingthe carbon dioxide enriched permeate stream (11) and recycling theoptionally compressed carbon dioxide enriched permeate stream (11) to beused as a supplemental feed stream processes other than the presentprocess; or recycled directly back to the carbon dioxide separation unit(4) for further processing. The carbon dioxide depleted residue stream(12) that is recovered, after optionally being turbo expanded in a turboexpander (22) (in order to recover compressed gas energy and use thisenergy to drive other components of the process) can be used as asupplemental feed for the pre-reformer (17) or the steam methanereformer (19). While it is possible to also use the carbon dioxidedepleted residue stream (12) as a supplemental fuel for the steammethane reformer (19), when higher levels of capture are desirable, theamount of residue stream (12) used as fuel will need to be minimized(when levels approaching 90% are desired) or eliminated (when levels ofcarbon dioxide capture approaching 100% are desired).

With regard to this particular process, it is possible to achieve anoverall capture rate of carbon dioxide that is equal to or greater than80%, even more preferably equal to or greater than 90%, and even stillmore preferably equal to or greater than 99%, and further stillapproaching or achieving 100% capture, when hydrogen fueling isutilized. Those of ordinary skill in the art will recognize that inorder to eliminate possible issues such as build up of inerts (e.g.,nitrogen) downstream of the pressure swing adsorption unit in thesystem, it may be desirable to configure the pressure swing adsorptionunit to allow for selectivity for those inerts thereby creating ahydrogen stream which is rich in inerts, this hydrogen stream that isrich in inerts to be used as fuel for the steam methane reformer unit(19).

In a broader aspect, the process for producing hydrogen and capturingcarbon dioxide from a hydrocarbon containing feed stream (16) in ahydrogen generation plant may be carried out utilizing any feed gasproducing unit (31) (see FIG. 7). As noted above, the preferred methodis carried out using a steam methane reformer (19) with a water gasshift reactor (21) and an optional pre-reformer (17). However, asdepicted in the embodiment set forth in FIG. 7, such feed gas producingunits (31) may also include POx units, ATR units, coal gasificationunits or refinery process units (where the feed gas (15) results fromrefinery processing; a refinery off gas) or any other feed gas producingunit that produces a gas mixture that contains at least hydrogen, carbonmonoxide and carbon dioxide. With regard to the embodiments whichcontain a gasification unit or a refinery process unit which produces afeed gas, in addition to the hydrogen rich permeate stream (8.2) beingrecycled for use as a supplemental feed for the process unit (0), thehydrogen rich permeate stream (8.1) may also be recycled back to thesource (feed gas producing unit 31) that produces the feed gas (15) thatis supplied to the process unit (0) (feed gas producing unit 31) to beused as a supplemental feed stream. More specifically, in addition tothe hydrogen permeate stream (8) being used in a schematic where it canbe used as a supplemental feed stream for the steam hydrocarbon reformerunit/water gas shift unit, this stream (8) may also be used as asupplemental feed stream for a POx unit, an ATR unit, a coalgasification unit or refinery process unit or other unit which producesa feed gas stream (15). As in the previous embodiment, it may beadvantageous to further heat the first hydrogen rich permeate fraction(8.1) prior to this stream being added as a supplemental feed to thestream of line (16). This combined fraction (8.1) and stream (16) arethen fed into the feed gas producing unit (31). While this heating maybe carried out in any manner known in the art, preferably the firsthydrogen rich permeate fraction (8.1) is heated utilizing a heatexchanger (30) specifically for this permeate fraction (8.1). Inaddition to heating this first hydrogen rich permeate fraction (8.1)before adding the fraction to the stream (16), steam can be injectedinto this fraction (8.1) via line (29) just prior to the fraction (8.1)being mixed with the stream (16). The heating of this first hydrogenrich permeate fraction (8.1) further improves the efficiency of therecycle.

With regard to the additional streams, while the hydrogen product stream(23) is recovered as product, as in the previous embodiments, a portionof this stream (23) can be used for hydrogen fueling of the feed gasproducing unit (31). In addition, as with the previous embodiments, thecarbon dioxide enriched permeate stream (11) may be recycled to theprocess stream (1) from the process unit (0) where is it added to theprocess stream (1) prior to the compressor (2) or within the compressor(2) between two of the stages of compression or optionally compressingthe carbon dioxide enriched permeate stream (11) and recycling theoptionally compressed carbon dioxide enriched permeate stream (11) to beused as a supplemental feed stream in other processes. The carbondioxide enriched permeate stream (11) may also be recycled directly backto the carbon dioxide separation unit (4) for further processing.

Note that the use of hydrogen selective membrane and carbon dioxideselective membrane is in order to increase the recovery of hydrogen andcarbon dioxide. This can boost hydrogen production and reduce carbondioxide emissions for the existing plants. It can also reduce the sizeof reformer, natural gas consumption for the same size new plants withreduced carbon dioxide emissions.

LIST OF ELEMENTS

-   0 process unit-   1 process stream-   2 first compressor-   3 heat exchanger-   4 carbon dioxide separation unit-   5 carbon dioxide lean non-condensable stream-   6 carbon dioxide rich liquid stream-   7 hydrogen selective membrane separation unit-   7.1 permeate side of hydrogen selective membrane-   7.2 residue side of hydrogen selective membrane-   8 hydrogen rich permeate stream-   8.1 first hydrogen rich permeate fraction-   8.2 second hydrogen rich permeate fraction-   9 hydrogen lean residue stream-   10 carbon dioxide selective membrane separation unit-   10.1 permeate side of carbon dioxide selective membrane-   10.2 residue side of carbon dioxide selective membrane-   11 carbon dioxide enrich permeate stream-   12 carbon dioxide depleted residue stream-   13 second compressor-   14 liquefaction unit-   14.1 first liquefaction unit-   14.2 second liquefaction unit-   15 feed gas-   16 hydrocarbon containing feed stream-   17 pre-reformer-   18 pre-reformed gas stream-   19 steam methane reformer unit-   20 syngas stream-   21 water gas shift reactor-   22 turbo expander-   23 hydrogen product stream from pressure swing adsorption unit-   24 distillation column-   25 additional compressor-   26 additional heat exchanger-   27 cooling element for additional compressor-   28 optional heat exchanger-   29 line for injecting steam into the first hydrogen rich permeate    fraction-   30 heat exchanger for recycle-   31 feed gas producing unit-   32 optional second water gas shift reactor-   33 optional third water gas shift reactor

1. A process for producing hydrogen and capturing carbon dioxide from ahydrocarbon containing feed stream (16) in a hydrogen generation plant,the process comprising the steps of: a) treating a hydrocarboncontaining feed stream (16) in a feed gas producing unit (31) to obtaina feed gas (15); b) subjecting the feed gas (15) to hydrogenpurification in a process unit (0) to obtain a hydrogen product stream(23) and a hydrogen depleted process stream (1); c) withdrawing thehydrogen product stream (23) and using a portion of this hydrogenproduct stream (23) as a fuel for the feed gas producing unit (31) or asfuel for steam generation; d) optionally compressing at least a portionof the process stream (1) in a first compressor (2); e) cooling theoptionally compressed portion of the process stream (1) in a heatexchanger (3) to a temperature equal to or less than −10° C.; f)separating and purifying the cooled process stream (1) in a carbondioxide separation unit (4) to produce a carbon dioxide rich liquidstream (6) and a carbon dioxide lean non-condensable stream (5); g)withdrawing the carbon dioxide rich liquid stream (6) as a carbondioxide product for further use; h) withdrawing the carbon dioxide leannon-condensable stream (5) from the carbon dioxide separation unit (4)and passing the carbon dioxide lean non-condensable stream (5) through ahydrogen selective membrane separation unit (7) to form a hydrogen richpermeate stream (8) with the remaining components in the carbon dioxidelean non-condensable stream (5) forming a hydrogen lean residue stream(9); i) passing the hydrogen lean residue stream (9) through a carbondioxide selective membrane separation unit (10) to form a carbon dioxideenriched permeate stream (11) with the remaining components in thehydrogen lean residue stream (9) forming a carbon dioxide depletedresidue stream (12); j) optionally compressing the hydrogen richpermeate stream (8) in a second compressor (13) and recycling thehydrogen rich permeate stream (8) for use as a supplemental feed streamin feed gas producing unit (31), the process unit (0) or in both; and k)recycling the carbon dioxide enriched permeate stream (11) to theprocess stream (1) prior to the compressor (2) or within the compressor(2) between stages of compression or optionally compressing the carbondioxide enriched permeate stream (11) and recycling the carbon dioxideenriched permeate stream (11) to be used in the carbon dioxideseparation unit (4) and recycling the carbon dioxide depleted residuestream (12) to be used as a supplemental feed stream for the feed gasproducing unit (31) or as both a fuel and a feed stream in the presentprocess or in other processes.
 2. The process of claim 1, wherein theoverall capture rate of carbon dioxide from the hydrogen productionprocess is equal to or greater than 80%.
 3. The process of claim 1,wherein the process unit (0) is a pressure swing adsorption unit and theprocess stream (1) is a tail gas from the pressure swing adsorptionunit.
 4. The process of claim 1, wherein the first hydrogen richpermeate fraction (8.1) is optionally heated prior to being added to thesyngas stream (20).
 5. The process of claim 1, wherein the hydrogenselective membrane separation unit (7) includes one or more hydrogenselective membranes, each membrane having a permeate side (7.1) and aresidue side (7.2) and allowing for the passing of hydrogen to thepermeate side (7.1) of the membrane to form the hydrogen rich permeatestream (8) with the remaining components in the carbon dioxide leannon-condensable stream (5) forming the hydrogen lean residue stream (9)on the residue side (7.2) of the membrane.
 6. The process of claim 5,wherein the carbon dioxide selective membrane separation unit (10)includes one or more carbon dioxide selective membranes, each membranehaving a permeate side (10.1) and a residue side (10.2) and allowing forthe passing of carbon dioxide to the permeate side (10.1) of themembrane to form a carbon dioxide enriched permeate stream (11) with theremaining components in the hydrogen lean residue stream (9) forming acarbon dioxide depleted residue stream (12) on the residue side (10.2)of the membrane.
 7. The process of claim 6, wherein the one or morehydrogen selective membranes and the one or more carbon dioxideselective membranes are each membranes of the fiber type.
 8. The processof claim 6, wherein the one or more hydrogen selective membranes aredifferent in type from the one or more carbon dioxide selectivemembranes.
 9. The process of claim 1, wherein prior to compression instep d), the process stream is passed through a filter.
 10. The processof claim 1, wherein the feed gas producing unit (31) is a coalgasification unit.
 11. The process of claim 1, wherein the feed gasproducing unit (31) is a partial oxidation unit.
 12. The process ofclaim 1, wherein the feed gas producing unit (31) is a autothermalreformer unit.
 13. The process of claim 1, wherein the hydrogen richpermeate stream (8) is subjected to a shift reaction in an optionalsecond water gas shift reactor (32) prior to being recycled to the watergas shift reactor (21), the process unit (0) or both the water gas shiftunit (21) and the process unit (0).
 14. The process of claim 13, whereinthe water gas shift reactor (32) is a low temperature water gas shiftreactor.
 15. The process of claim 1, wherein the carbon dioxide leannon-condensable stream (5) is subjected to a shift reaction in anoptional third water gas shift reactor (33) prior to being passedthorough the hydrogen and carbon dioxide membrane separation units (7,10).
 16. The process of claim 15, wherein the water gas shift reactor(33) is a low temperature water gas shift reactor.